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    Investor Presentation Investor Presentation Presentation Transcript

    • 1INVESTOR PRESENTATION 5-7-2014 INVESTOR PRESENTATION LAST UPDATED 5-7-2014
    • 2INVESTOR PRESENTATION 5-7-2014 FORWARD-LOOKING STATEMENTS • This presentation includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are statements other than those of historical fact that give our current expectations or forecasts of future events. They include production forecasts, estimates of operating costs, assumptions regarding future natural gas and liquids prices, planned drilling activity and drilling and completion capital expenditures, as well as projected cash flow, business strategy and other plans and objectives for future operations. Although we believe the expectations and forecasts reflected in forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate or changed assumptions or by known or unknown risks and uncertainties. • Disclosures concerning the estimated contribution of derivative contracts to our future results of operations are based upon market information as of a specific date, and such market prices are subject to significant volatility. Our production forecasts are dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. • Factors that could cause actual results to differ materially from expected results are described under “Risk Factors” in Item 1A of our 2013 annual report on Form 10-K filed with the U.S. Securities and Exchange Commission on February 27, 2014. These risk factors include the volatility of natural gas, oil and NGL prices; the limitations our level of indebtedness may have on our financial flexibility; declines in the prices of natural gas and oil potentially resulting in a write-down of our asset carrying values; the availability of capital on an economic basis, including through planned asset sales to fund reserve replacement costs; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of natural gas, oil and NGL reserves and projecting future rates of production and the amount and timing of development expenditures; our ability to generate profits or achieve targeted results in drilling and well operations; leasehold terms expiring before production can be established; hedging activities resulting in lower prices realized on natural gas, oil and NGL sales; the need to secure hedging liabilities and the inability of hedging counterparties to satisfy their obligations; drilling and operating risks, including potential environmental liabilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing, air emissions and endangered species; a deterioration in general economic, business or industry conditions having a material adverse effect on our results of operations, liquidity and financial condition; oilfield services shortages, gathering system and transportation capacity constraints and various transportation interruptions that could adversely affect our revenues and cash flow; adverse developments and losses in connection with pending or future litigation and regulatory investigations; cyber attacks adversely impacting our operations; and an interruption at our headquarters that adversely affects our business • In addition, disclosures concerning the estimated contribution of derivative contracts to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility. Our production forecasts are also dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. Further, the timing of and amount of proceeds from future asset sales, which are subject to changes in market conditions and other factors beyond our control, will affect our ability to further reduce financial leverage and complexity. We caution you not to place undue reliance on our forward- looking statements, which speak only as of the date of this presentation or as otherwise indicated, and we undertake no obligation to update this information, except as required by applicable law.
    • 3INVESTOR PRESENTATION 5-7-2014 1Q’14 FINANCIAL RESULTS (1) G&A excludes expenses associated with share-based compensation and restructuring and other termination costs (2) Includes unrestricted cash and borrowing availability under revolving credit facilities as of 3/31/2014 (3) Includes $362 mm for compression assets sold to Exterran Partners, $209 mm for Chaparral Energy common equity, $159 mm for compression units sold to Access Midstream Partners, $195 mm for real estate and other miscellaneous noncore assets Note: Reconciliation of non-GAAP measures to comparable GAAP measures appear on pages 21-22 PROD. and G&A EXP. $5.0billion(2) LIQUIDITY YTD ASSET SALES TOTAL CAPEX $925 million(3) 50%YOY $850 million ADJ. EARNINGS/FDS 97%YOY $0.59 ADJ. EBITDA 34%YOY $1.5 billion 12%YOY $5.83/boe(1)
    • 4INVESTOR PRESENTATION 5-7-2014 1Q’14 OPERATIONAL RESULTS (1) Oil and NGL collectively referred to as “liquids” 11%YOY 675.2 mboe/d TOTAL ADJ. PROD. LIQUIDS MIX 29% 24% in 1Q’13 20%YOY 109.5 mbbls/d of Total Production(1) to ADJ. NGL PRODUCTION 63%YOY 84.2 mbbls/d ADJ. NATURAL GAS 4%YOY 2.9 bcf/d ADJ. OIL PRODUCTION
    • 5INVESTOR PRESENTATION 5-7-2014 KEY STRATEGIC TENETS • Financial discipline ˃ Balance capex with operating cash flow ˃ Divest noncore assets and noncore affiliates ˃ Reduce financial and operational risk and complexity ˃ Achieve investment grade metrics • Profitable and efficient growth from captured resources ˃ Develop world-class inventory ˃ Target top-quartile operating and financial metrics ˃ Pursue continuous improvement ˃ Drive value leakage out of operations
    • 6INVESTOR PRESENTATION 5-7-2014 Powder River Basin: Niobrara Shale Mid-Continent: Mississippian Lime Mid-Continent: Cleveland and Tonkawa Tight Sands Mid-Continent: Colony Wash and Texas Panhandle Granite Wash Eagle Ford Shale Utica Shale Marcellus Shale Barnett Shale Haynesville Shale OPERATING AREAS
    • 7INVESTOR PRESENTATION 5-7-2014 ADJUSTED PRODUCTION GROWTH Oil (mmbbls) 41.1 (2.6) 38.5 8 – 12% NGL (mmbbls) 20.9 (0.5) 20.4 58 – 63% Natural Gas (bcf) 1,095 (60) 1,035 4 – 6% Total (mmboe) 244.4 (13.1) 231.4 9 – 12% 2014E Adjusted Production Growth 2013 Reported Production 2013 Asset Sales 2013 Adjusted Production 7 2013 Asset Sale Adjustments (mmboe) 252 - 259 2014E Production 2013 Adjusted Production (4.8) (3.6) (3.5)(1.2) 231 244 2013 Reported Production N. Eagle Ford Haynesville Miss. Lime JV Marcellus
    • 8INVESTOR PRESENTATION 5-7-2014 CAPITAL DISCIPLINE 2014 total capital expenditures expected to range from $5.2 – $5.6 billion; planned reduction of >20% YOY and ~60% compared to 2010-12 average (1) Based on midpoints of company-issued Outlook ranges provided on 5/7/2014 (2) Includes only cash related hedging gains/losses and excludes noncash amortization (1) (2)
    • 9INVESTOR PRESENTATION 5-7-2014 CASH COST DISCIPLINE (2) (1) Based on midpoints of company-issued Outlook ranges provided on 5/7/2014 (2) G&A excludes expenses associated with share-based compensation and restructuring and other termination costs (1)
    • 10INVESTOR PRESENTATION 5-7-2014 • 2014E total capital expenditures expected to range from $5.2 – $5.6 billion ˃ E&P capex 90-95% of total • Capturing substantial supply chain management efficiencies • Continuous investment high grading and post appraisal process 2014 CAPITAL ALLOCATION E&P Capex by Play(1) ~80% ~20% Liquids Gas E&P Capex by Product(1) (1) Net of $596 mm and $135 mm drilling carries remaining at 12/31/2013 in the Utica and PRB, respectively; includes drilling, completion, leasehold, geological and geophysical costs and capitalized G&A; excludes capitalized interest (2) Includes Mississippian Lime, Cleveland, Tonkawa, Colony and Texas Panhandle Granite Washes and other Anadarko plays (2)
    • 11INVESTOR PRESENTATION 5-7-2014 (discount to Henry Hub) Marcellus North Haynesville Marcellus South Utica Barnett Mid-Continent Eagle Ford Rockies Weighted Average REGIONAL NATURAL GAS DIFFERENTIALS ($1.30 – $1.40)/mcf ($1.40 – $1.50)/mcf ($1.95 – $2.05)/mcf ($1.25 – $1.35)/mcf ($2.95 – $3.05)/mcf ($0.90 – $1.00)/mcf ($3.05 – $3.15)/mcf ($2.70 – $2.80)/mcf ($1.60 – $1.70)/mcf 2014E
    • 12INVESTOR PRESENTATION 5-7-2014 1Q’14A Diff. to HH April - Oct ‘14 Basis Hedges April - Oct ‘14 Hedged Volumes (mmcf/d) Tetco M3/Transco z6 NYC $3.25 ($0.62) 240 Dominion South ($0.49) ($0.90) 30 WTD. Avg. Basis Hedged April – Oct ‘14 ($0.68) NE MARCELLUS SALES POINTS AND BASIS HEDGES 34% 9% 9%3% 36% 9% Tetco M3/TCO z6 (NYC) Dominion South Point TGP Zn1 500 Line TGP Zn4 200L In-Basin Firm In-Basin Floating Estimated April - Oct ‘14 NE Sales Points • ~38% of estimated April-October 2014 natural gas production will receive an avg. basis differential of ($0.68)/mcf • ~10% of estimated April-October 2014 natural gas production will receive Gulf Coast linked pricing • ~35% of April-October 2014E natural gas production sold in-basin under firm purchase agreements
    • 13INVESTOR PRESENTATION 5-7-2014 1Q’14A Diff. to HH April - Oct ‘14 Basis Hedges April - Oct ‘14 Hedged Volumes (mmcf/d) TCO ($0.03) ($0.22) 105 Dominion South ($0.49) ($0.90) 45 WTD. Avg. Basis Hedged April – Oct ‘14 ($0.42/mcf) UTICA AND SOUTHERN MARCELLUS SALES POINTS 39% 18% 21% 6% 10% 6% TGP Zn1 500L (Gulf Coast) Dominion South Point TGP Zn4 200L TETCO M3 TCO TETCo M2 30% 39% 10% 13% 8% TGP Zn1 500L (Gulf Coast) Tetco WLA (Gulf Coast) Dominion South Point TGP Zn4 200L TCO Estimated April - Oct ‘14 Sales Points Estimated 2015 Sales Points • ~31% of estimated April-October 2014 natural gas production will receive an average differential of ($0.42)/mcf • ~40% and ~70% of 2014E and 2015E natural gas will receive Gulf Coast linked pricing, respectively
    • 14INVESTOR PRESENTATION 5-7-2014 41 - 48 Liquids Focused Rigs 14 - 17 Natural Gas Focused Rigs 55 - 65 Total Operated Rigs OPERATIONS 1Q’14 Daily Avg. Net Production (mboe/d)2014E Avg. Operated Rig Count (1) Includes Mississippian Lime, Cleveland, Tonkawa, Colony and Texas Panhandle Granite Washes and other Anadarko plays +11%YOY avg. net production adjusted for asset sales
    • 15INVESTOR PRESENTATION 5-7-2014 ($mm) 12/31/2013 3/31/2013 3/31/2014 Unrestricted cash $837 $33 $1,004 +$167 +$971 Working capital(1)(2) ($2,696) ($2,934) ($2,371) +$325 +$563 Other long-term liabilities(2) $984 $1,132 $851 +$133 +$281 Debt, net of disc.(3) $12,886 $13,449 $12,969 -$83 +$480 Total net debt & BS Impr. $15,729 $17,482 $15,187 +$542 +$2,295 Net debt/total cap.(4) 40% 43% 39% (1) Excludes unrestricted cash and current maturities of long-term debt (2) Excludes deferred income taxes, long-term derivative liabilities and asset retirement obligation (3) Includes current maturities of long-term debt (4) Net debt is total debt net of unrestricted cash BALANCE SHEET IMPROVEMENT Seq. YOY
    • 16INVESTOR PRESENTATION 5-7-2014 SENIOR NOTE PROFILE $1,500 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 $396 $2,305 $1,015 $1,800 $1,100 $2,150 $1,700 9.50% 3.25% 5.75%(2) 6.875% 3mL+3.25%(4) 6.875% 5.375% 4.875% 5.75% 2.75%(1) 2.5%(1) 2.25%(1) 6.625%(5) 6.625% 6.125% 6.5% 7.25% 6.25%(3) $500 As of 3/31/2014 pro forma for April 2014 refinancing ($ in mm) (1) Recognizes earliest investor put option as maturity for the 2.75% 2035, 2.5% 2037 and 2.25% 2038 Contingent Convertible Senior Notes (2) Interest at LIBOR plus 4.50%; LIBOR rate is subject to a floor of 1.25% per annum (3) Euro-denominated notes with a principal amount based on the exchange rate of $1.3855 to €1.00 at 4/9/2014 (4) All in yield composed of 3.25% spread and 3mL (5) COO $650mm Senior Notes due 2019 Debt Targeted for Retirement Convertibles Notes Issued April 2014 Other Senior Notes 12/31/2013 WACD – 5.912% WACD pro forma for 4/14 issuance – 5.148% ~$115 mm in annual cash savings $0
    • 17INVESTOR PRESENTATION 5-7-2014 2014 HEDGES Note: Hedged positions as of 5/1/2014 based on production estimates provided in 5/7/2014 Outlook; 22% of 2014 gas production is hedged under three-way collar arrangements with upside to average NYMEX price of $4.38/mcf and exposure below average NYMEX price of $3.53/mcf 70% Natural Gas Oil $94.32/bbl NYMEX 64% 40% Swaps 22% Three-way Collars $4.10 - $4.38/mcf NYMEX $4.08/mcf NYMEX $4.51-$5.25/mcf NYMEX
    • 18INVESTOR PRESENTATION 5-7-2014 2014 OUTLOOK (1) Growth ranges based on 2013 production of 634 mboe/day adjusted for asset sales as provided in 5/7/2014 Outlook (2) Assumes ethane recovery in the Utica and southern Marcellus to fulfill Chesapeake’s pipeline commitments, no ethane recovery in the Rockies and the Eagle Ford and partial ethane recovery in the Mid-Continent (3) NYMEX natural gas and oil prices have been updated for actual contract prices through April and March, respectively (4) G&A excludes expenses associated with share-based compensation and restructuring and other termination costs (5) A non-GAAP financial measure. We are unable to provide reconciliation to projected cash provided by operating activities, the most comparable GAAP measure, because of uncertainties associated with projecting future changes in assets and liabilities (6) The new guidance presentation we have adopted includes only cash related hedging gains/losses and excludes noncash amortization. Previous Outlook guidance treated all realized hedging gains/losses as cash and all unrealized gains/losses as noncash. However, a portion of realized hedging gains/losses actually consists of noncash amortization from previously closed out hedges. Please note that cash flow from operating activities on a GAAP basis is unaffected by this presentation change 2014E - NEW Adjusted production growth(1) : Liquids 25 – 29% Oil 8 – 12% NGL(2) 58 – 63% Natural gas 4 – 6% Total 9 – 12% Daily rate (mboe) 690 – 710 % of production mix from liquids 29% % O/G revenues from liquids(3) 62% Operating costs per boe: Production expenses, production taxes and G&A(4) $6.30 – $7.00 Operating cash flow ($mm)(3)(5)(6) $5,800 – $6,000 Total capital expenditures ($mm) $5,200 – $5,600 Capitalized interest, dividends and distributions ($mm) $1,150 – $1,200 18
    • 19INVESTOR PRESENTATION 5-7-2014 NEAR-TERM PRIORITIES • Capital Efficiency • Balance Sheet Improvement • Cash Flow Growth Analyst Day: May 16th, 2014 - Oklahoma City, OK
    • 20INVESTOR PRESENTATION 5-7-2014 APPENDIX
    • 21INVESTOR PRESENTATION 5-7-2014 (1) Adjusted net income available to common stockholders and adjusted earnings per share assuming dilution exclude certain items that management believes affect the comparability of operating results. The company believes these adjusted financial measures are a useful adjunct to earnings calculated in accordance with accounting principles generally accepted in the United States (GAAP) because: (i) Management uses adjusted net income available to common stockholders to evaluate the company's operational trends and performance relative to other natural gas and oil producing companies. (ii) Adjusted net income available to common stockholders is more comparable to earnings estimates provided by securities analysts. (iii) Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items. (2) In millions. Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP ($ in mm, except per share data) Three Months Ended: 3/31/2014 3/31/2013 Net income available to common stockholders $374 $15 Adjustments, net of tax: Unrealized losses on derivatives 80 94 Restructuring and other termination costs (4) 83 Impairments of fixed assets and other 12 16 Net gains on sales of fixed assets (14) (30) Losses on investments – 6 Net gains on sales of investments (42) – Other (1) (1) Adjusted net income available to common stockholders(1) $405 $183 Preferred stock dividends 43 43 Earnings allocated to participating securities 8 – Total adjusted net income attributable to CHK $456 $226 Weighted average fully diluted shares outstanding(2) 767 761 Adjusted earnings per share assuming dilution(1) $0.59 $0.30 RECONCILIATION
    • 22INVESTOR PRESENTATION 5-7-2014 RECONCILIATION (1) Operating cash flow represents net cash provided by operating activities before changes in assets and liabilities. Operating cash flow is presented because management believes it is a useful adjunct to net cash provided by operating activities under GAAP. Operating cash flow is widely accepted as a financial indicator of a natural gas and oil company's ability to generate cash which is used to internally fund exploration and development activities and to service debt. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies within the natural gas and oil exploration and production industry. Operating cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities as an indicator of cash flows, or as a measure of liquidity. (2) Ebitda represents net income (loss) before interest expense, income taxes, and depreciation, depletion and amortization expense. Ebitda is presented as a supplemental financial measurement in the evaluation of our business. We believe that it provides additional information regarding our ability to meet our future debt service, capital expenditures and working capital requirements. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies. Ebitda is also a financial measurement that, with certain negotiated adjustments, is reported to our lenders pursuant to our bank credit agreements and is used in the financial covenants in our bank credit agreements. Ebitda is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations or cash flow provided by operating activities prepared in accordance with GAAP. (3) Adjusted ebitda excludes certain items that management believes affect the comparability of operating results. The company believes these non-GAAP financial measures are a useful adjunct to ebitda because: (i) Management uses adjusted ebitda to evaluate the company's operational trends and performance relative to other natural gas and oil producing companies. (ii) Adjusted ebitda is more comparable to estimates provided by securities analysts. (iii) Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items. ($ in mm) Three Months Ended: 3/31/2014 3/31/2013 Cash provided by operating activities $1,291 $924 Changes in assets and liabilities 323 255 Operating cash flow(1) $1,614 $1,179 Net income $466 $102 Interest expense 39 21 Income tax expense 280 63 Depreciation and amortization of other assets 78 78 Natural gas, oil and NGL depreciation, depletion and amortization 628 648 EBITDA(2) $1,491 $912 Adjustments: Unrealized losses on natural gas, oil and NGL derivatives 144 146 Restructuring and other termination costs (7) 133 Impairments of fixed assets and other 20 27 Net gains on sales of fixed assets (23) (49) Losses on investments – 10 Net gains on sales of investments (67) – Net income attributable to noncontrolling interests (41) (44) Other (2) (1) Adjusted EBITDA(3) $1,515 $1,134
    • 23INVESTOR PRESENTATION 5-7-2014 PUBLICLY TRADED SECURITIES CUSIP TICKER 9.5% Senior Notes due 2015 #165167CD7 CHK15K 3.25% Senior Notes due 2016 #165167CJ4 CHK16 6.25% Senior Notes due 2017 #027393390 N/A 6.50% Senior Notes due 2017 #165167BS5 CHK17 7.25% Senior Notes due 2018 #165167CC9 CHK18A 3mL + 3.25% Senior Notes due 2019 #165167CM7 TBD 6.625% Senior Notes due 2020 #165167CF2 CHK20A 6.875% Senior Notes due 2020 #165167BU0 CHK20 6.125% Senior Notes Due 2021 #165167CG0 CHK21 5.375% Senior Notes Due 2021 #165167CK21 CHK21A 4.875% Senior Notes Due 2022 #165167CN5 TBD 5.75% Senior Notes Due 2023 #165167CL9 CHK23 2.75% Contingent Convertible Senior Notes due 2035 #165167BW6 CHK35 2.50% Contingent Convertible Senior Notes due 2037 #165167BZ9/ #165167CA3 CHK37/ CHK37A 2.25% Contingent Convertible Senior Notes due 2038 #165167CB1 CHK38 4.5% Cumulative Convertible Preferred Stock #165167842 CHK PrD 5.0% Cumulative Convertible Preferred Stock (Series 2005B) #165167834/ #165167826 N/A 5.75% Cumulative Convertible Preferred Stock #U16450204/ #165167776/ #165167768 N/A 5.75% Cumulative Convertible Preferred Stock (Series A) #U16450113/ #165167784/ #165167750 N/A Chesapeake Common Stock #165167107 CHK CORPORATE INFORMATION 6100 N. Western Avenue Oklahoma City, OK 73118 WEBSITE: www.chk.com CHESAPEAKE HEADQUARTERS GARY T. CLARK, CFA Vice President — Investor Relations and Research DOMENIC J. DELL'OSSO, JR. Executive Vice President and Chief Financial Officer Investor Relations department can be reached by phone at (405) 935-8870 or by email at ir@chk.com TWITTER.COM/CHESAPEAKE FACEBOOK.COM/CHESAPEAKE YOUTUBE.COM/CHESAPEAKE CORPORATE CONTACTS